Virginia Hills Oil Corp. Announces Third Quarter 2015 Results

CALGARY, Nov. 27, 2015 /CNW/ – Virginia Hills Oil Corp. (“Virginia Hills” or the “Company“) announces its operating and financial results for the three and nine months ended September 30, 2015 and that its unaudited interim financial statements and related Management's Discussion and Analysis (“MD&A”) for the quarter ended September 30, 2015 are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com or on the Company's website at www.virginiahillsoil.com.

THIRD QUARTER 2015 FINANCIAL AND OPERATIONAL HIGHLIGHTS

Three months ended September 30

Nine months ended September 30

2015

2014 (2)

2015

2014 (2)

FINANCIAL ($000, except per share amounts)

Petroleum and natural gas sales

8,302

15,018

23,738

51,414

Funds flow from operations (1)

1,079

4,245

3,502

17,432

Per share – basic

$0.05

$1.95

$0.29

$8.03

Per share – diluted

$0.05

$1.92

$0.29

$7.87

Net income (loss)

(3,098)

51

340

748

Per share – basic

$(0.16)

$0.02

$0.03

$0.34

Per share – diluted

$(0.16)

$0.02

$0.03

$0.34

Capital expenditures

7,246

2,846

10,093

4,631

Net debt (1)(3)

110,949

113,519

110,949

113,519

Common Shares Outstanding (2)

Weighted average – basic

19,724

2,172

12,050

2,172

Weighted average – diluted

19,724

2,214

12,050

2,218

Total outstanding

19,724

2,172

12,050

2,172

OPERATING

Number of days

92

92

273

273

Production

Oil and NGL (bbl/d)

1,416

1,756

1,482

1,943

Natural gas (mcf/d)

325

316

304

379

Total production (boe/d)

1,470

1,809

1,533

2,006

Average realized price(4)

Oil and NGL ($/bbl)

63.44

92.92

58.49

96.86

Natural gas ($/mcf)

1.18

0.10

0.89

0. 38

Netback per boe ($)(1)

Petroleum and natural gas sales

61.36

90.24

56.73

93.88

Royalties

(6.53)

(18.44)

(5.14)

(17.14)

Production and transportation expenses

(29.85)

(32.06)

(26.86)

(28.10)

Field netback(1)

24.98

39.74

24.73

48.64

Realized loss on derivative financial instruments

–

(1.95)

–

(2.88)

Operating netback(1)

24.98

37.79

24.73

45.76

Drilling

Gross wells

2.0

–

2.0

–

Net wells

2.0

–

2.0

–

(1) Non-GAAP measures and non-GAAP measures advisory.

(2) Share and per share amounts for comparative periods reflect the 100:1 share consolidation as though the consolidation took place at the beginning of the earliest period.

(4) Before the effects of derivative financial instruments, but includes gains or losses on fixed price, physical contracts that are not considered derivative instruments.

OPERATIONS UPDATE AND OUTLOOK

Low commodity prices through-out the first nine months of 2015 continue to present a challenging business environment for the Canadian oil and gas industry. The price of WTI averaged US$46.43 per barrel during the third quarter of 2015, down 52% from US$97.17 per barrel during the comparable period in 2014. Benchmark price decreases have been offset to some extent by the strong U.S dollar, which has resulted in an increase in the commodity prices realized in Canada. Virginia Hill's realized pricing for the third quarter of 2015 was $61.36 per boe compared to $90.24 per boe for the third quarter of 2014, and averaged $56.73 per boe for the first nine months of 2015 compared to $93.88 per boe for the same period in 2014. Virginia Hill's production in the third quarter was weighted 96% to light oil and natural gas liquids, as a result the Company's realized product pricing per unit has and will continue to track closely to oil pricing. Although the Company anticipates that the oil supply and demand balance will stabilize in 2016, the return of 2014 pricing levels is not expected for a considerable amount of time. Consequently, Virginia Hills is anticipating average oil pricing for 2016 and 2017 at $50.00 US per bbl WTI and $55.00 US per bbl WTI, respectively.

Production volumes for the three and nine months ending September 30, 2015 averaged 1,470 boe/d and 1,533 boe/d, respectively, representing declines of 19 percent and 24 percent from 2014 levels. Production in the third quarter and year to date was negatively impacted by the sale of approximately 100 boe/d of production in the second quarter of 2015. In addition, the Company shut-in production of approximately 40 boe/d due to negative economics associated with the lower commodity price environment and no material production was added from new wells during the first nine months of 2015. Taking into account the disposition and the uneconomic shut-in production, the Company's remaining light oil production base has declined at a rate that remains below 15% annually over the prior year.

Management continues to focus on the operating cost structure of its Red Earth production and was successful in reducing production and transportation expenses in the third quarter and year to date from 2014 levels by 24 percent and 27 percent, respectively. Production expenses were down by 28 percent to $3.5 million in the third quarter of 2015 from $4.8 million in the comparable 2014 quarter. Per unit costs excluding transportation costs in the third quarter of 2015 were $25.73 per boe representing an 11 percent decrease from the third quarter of 2014.

Total operating expenses (production and transportation expense) were $11.2 million for the nine months ended September 30, 2015 compared to $15.4 million in 2014, representing a decrease of 27 percent year over year. The decrease in total operating expenses is due primarily to various operational cost efficiency initiatives and a decline in base production rates. On a per unit basis total operating expenses over the first nine months of 2015 dropped 4 percent to $26.86 per boe from $28.10 per boe in 2014.

Year to date expense reductions were offset, in part, by non-recurring costs of approximately $0.7 million associated with the clean-up of an emulsion pipeline break that occurred in the second quarter of 2015. Clean-up cost associated with the pipeline break had a negative impact on operating costs of approximately $1.79 per boe for the nine months ended September 30, 2015 with costs incurred in the third quarter of approximately $0.1 million representing a negative impact of $0.69 per boe for the third quarter.

Despite these cost savings initiatives, low commodity prices and lower average production volumes have directly impacted the Company's field netback for the third quarter ended September 30, 2015, which was $3.4 million ($24.98 per boe), compared to $8.2 million ($39.74 per boe) for the third quarter ended September 30, 2014. During the third quarter of 2015, Virginia Hills' initiated its first capital program in the Red Earth area and spent approximately $7.2 million on capital activities drilling 2.0 gross (2.0 net) horizontal light oil wells in addition to the purchase and installation of certain facilities and pipelines associated with the Company's water flood projects.

In the third quarter of 2015, the Company invested $2.6 million on optimizing its Slave Point water flood projects in the Red Earth area including certain pipelines and facility improvements and initiating the electrification of its water flood facilities and producing wells. It is anticipated that these projects will allow the Company to increase its total water injection rates, under a lower cost structure, so that it can start to materially re-pressure the Slave Point reservoir. These projects did not provide any incremental production in the third quarter however the Company anticipates significant production and reserves additions concurrent with lower overall per unit operating costs within its water flood project areas over the next 12 to 24 months as these improvements take full effect.

The Company completed the majority of its 2015 capital program as planned in the third quarter. Virginia Hills remained focused on maximizing the rate of return associated with these projects which lead to certain cycle time delays as the Company actively pursued the lowest cost solutions in a very volatile commodity and service price environment. As a result of the delays associated with the start-up of these projects Virginia Hills is expecting full year production to average between 1,515 boe per day and 1,565 boe per day with exit production to range between 1,600 boe per day and 1,650 boe per day.

Through the optimization of its extensive Red Earth water flood project area, Virginia Hills believes it is positioned to add a substantial amount of production and reserves with very little incremental capital over the next 12 to 24 month period. These low cost water flood additions are expected to allow the Company to operate a capital program that is significantly below its free cash flow level over this time period which will provide the opportunity for meaningful debt reduction and value creation for its shareholders. The Company maintains a risked and total unrisked undeveloped light oil horizontal drilling inventory in its Red Earth core area of 81 net wells and 176 net wells, respectively, representing over 15 years of potential drilling activity. With this undeveloped light oil drilling inventory and its substantial operated water flood infrastructure foot print in the Red Earth area, Virginia Hills remains uniquely positioned to enter a more meaningful drilling and production growth phase as commodity prices return to more historical levels in the next 24 month period.

Advisories & Contact

FORWARD-LOOKING STATEMENTS: This news release contains forward-looking statements. More particularly, this news release contains forward-looking statements concerning: the timing for the stabilization of commodity prices; average oil prices for 2016 and 2017; the ability of the Company to decrease overall well costs; increases in future production rates on the wells drilled and completed in the third quarter of 2015; the success of the Company's Slave Point water flood projects; the ability of the Company to increase water injection rates; the ability of the Company to re-pressure the Slave Point reservoir; the results of the Company's water flood projects over the course of the next 12 to 24 months; future decreases to per unit operating costs within water flood project areas; the Company's average production rate and exit rate for 2015; the ability of the Company to add production and reserves through its Red Earth water flood projects; the ability of the Company to reduce its outstanding debt; the amount of capital that the Company will need to expend to fund its Red Earth water flood projects; the ability of the Company to operate a capital program below its free cash flow levels; and the number of drilling locations. In addition, the use of any of the words “guidance”, “initial, “scheduled”, “can”, “will”, “prior to”, “estimate”, “anticipate”, “believe”, “potential”, “should”, “unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, “project”, and similar expressions are intended to identify forward-looking statements.

The forward-looking statements contained in this news release are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning: the success of optimization and efficiency improvement projects; the success of the water flood projects and the timing thereof; the availability of capital; the success of future drilling and development activities; the performance of existing wells; the performance of new wells; the timing, cost and ability to access, maintain or expand necessary facilities and/or secure adequate product transportation and storage; the ability to successfully market the Company's petroleum and natural gas products; surface rights access being granted to the Company; the ability of the Company to obtain and retain qualified staff and services in a timely and cost efficient manner; the absence of any material litigation or claims against the Company; the general stability of the economic and political environment and the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company has an interest in oil and natural gas properties; and future crude oil, natural gas and NGL prices and currency, exchange and interest rates. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties.

Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: volatility in the demand, supply and market prices for crude oil, natural gas and NGL; volatility in exchange rates; liabilities inherent in petroleum and natural gas operations; uncertainties associated with estimating crude oil, natural gas and NGL reserves and future production levels; increased operating costs incurred by the Company; competition for, among other things, capital and acquisitions of reserves, additional petroleum and natural gas assets and undeveloped lands; incorrect assessments of the value of acquisitions; risks related to the environment and changing environmental laws in relation to the operations by the Company; geological, technical, drilling and completions, processing and handling issues associated with petroleum and natural gas development activities by third parties; claims made or legal actions brought or realized against the Company, its properties or assets; a failure by the Company to hire or retain key personnel; general economic, market and business conditions; and changes in tax or environmental laws or royalty or incentive programs relating to the oil and natural gas industry.

The forward-looking statements contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

NON-GAAP MEASURES: This news release contains the terms “funds flow from operations”, “net debt”, “field netback” and “operating netback” which do not have a standardized meaning prescribed by Canadian generally accepted accounting principles (“GAAP“) and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds flow from operations to analyze operating performance and leverage. Management believes “net debt” is a useful supplemental measure of the total amount of current and long-term debt of the Company.. Management believes “field netback” and “operating netback” are useful supplemental measures of the amount of revenues received after royalties and production and transportation costs, and the amount of revenues received after royalties, operating, transportation costs and realized gain (loss) on derivatives. Additional information relating to certain of these non-GAAP measures, including the reconciliation between funds flow from operations and cash flow from operating activities can be found in the MD&A.

BOE ADVISORY: To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

DRILLING LOCATIONS: This news release discloses unbooked drilling locations associated with the Company's core properties. The unbooked locations are Virginia Hills' internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Drilling locations have been identified by the Company's management as an estimation of the Company's expected multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all identified drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves or resources for Virginia Hills. The drilling locations on which the Company actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

INITIAL PRODUCTION RATES: Any references in this news release to initial production rates or flow back production results are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.